PHX Minerals (PHX) 10-Q 7 Aug 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Jun. 30, 2017	Aug. 07, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	315,131
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		16,671,016

Condensed Balance Sheets

Condensed Balance Sheets - USD ($)		Jun. 30, 2017	Sep. 30, 2016
Current assets:
Cash and cash equivalents		$ 560,892	$ 471,213
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,851,996	5,287,229
Refundable income taxes		571,986	83,874
Derivative contracts, net	[1]	1,439,686
Other		222,675	419,037
Total current assets		8,647,235	6,261,353
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		443,928,828	434,469,093
Non-producing oil and natural gas properties		7,462,082	7,574,649
Other		1,064,172	1,069,658
Gross properties and equipment, at cost, based on successful efforts accounting		452,455,082	443,113,400
Less accumulated depreciation, depletion and amortization		(255,806,129)	(251,707,749)
Net properties and equipment		196,648,953	191,405,651
Investments		168,209	157,322
Derivative contracts, net	[1]	11,711
Total assets		205,476,108	197,824,326
Current liabilities:
Accounts payable		3,791,830	2,351,623
Derivative contracts, net	[1]		403,612
Accrued liabilities and other		1,758,153	1,718,558
Total current liabilities		5,549,983	4,473,793
Long-term debt		50,000,000	44,500,000
Deferred income taxes, net		30,825,007	30,676,007
Asset retirement obligations		3,114,867	2,958,048
Derivative contracts, net	[1]		24,659
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 16,863,004 issued at June 30, 2017, and September 30, 2016		280,938	280,938
Capital in excess of par value		2,531,822	3,191,056
Deferred directors' compensation		3,367,432	3,403,213
Retained earnings		112,962,754	112,482,284
Stockholders' Equity		119,142,946	119,357,491
Less treasury stock, at cost; 191,988 shares at June 30, 2017, and 262,708 shares at September 30, 2016		(3,156,695)	(4,165,672)
Total stockholders' equity		115,986,251	115,191,819
Total liabilities and stockholders' equity		$ 205,476,108	$ 197,824,326
[1]	See Fair Value Measurements section for further disclosures regarding fair value of financial instruments

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2017	Sep. 30, 2016
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.0166	$ 0.0166
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	16,863,004	16,863,004
Treasury stock, shares	191,988	262,708

Condensed Statements Of Operati

Condensed Statements Of Operations - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Revenues:
Oil, NGL and natural gas sales	$ 9,997,898	$ 7,365,898	$ 27,788,018	$ 22,557,372
Lease bonuses and rentals	819,591	4,281,095	3,991,752	7,188,152
Gains (losses) on derivative contracts	1,619,697	(1,782,903)	1,658,347	(842,726)
Total revenues	12,437,186	9,864,090	33,438,117	28,902,798
Costs and expenses:
Lease operating expenses	3,391,079	3,520,196	9,545,990	10,274,085
Production taxes	390,387	196,733	1,129,785	747,714
Depreciation, depletion and amortization	4,714,350	5,959,482	13,654,268	18,963,017
Provision for impairment	0	0	10,788	11,849,064
Loss (gain) on asset sales and other	11,447	17,223	98,445	(187,692)
Interest expense	306,161	331,117	884,928	1,034,027
General and administrative	1,796,004	1,570,134	5,358,114	5,133,657
Total costs and expenses	10,609,428	11,594,885	30,682,318	47,813,872
Income (loss) before provision (benefit) for income taxes	1,827,758	(1,730,795)	2,755,799	(18,911,074)
Provision (benefit) for income taxes	567,000	(944,000)	263,000	(7,887,000)
Net income (loss)	$ 1,260,758	$ (786,795)	$ 2,492,799	$ (11,024,074)
Basic and diluted earnings (loss) per common share	$ 0.07	$ (0.05)	$ 0.15	$ (0.65)
Basic and diluted weighted average shares outstanding:
Common shares	16,668,814	16,582,416	16,639,090	16,575,117
Unissued, directors' deferred compensation shares	254,891	263,649	277,294	259,382
Basic and diluted weighted average shares outstanding	16,923,705	16,846,065	16,916,384	16,834,499
Dividends declared per share of common stock and paid in period	$ 0.04	$ 0.04	$ 0.12	$ 0.12

Statements Of Stockholders' Equ

Statements Of Stockholders' Equity - USD ($)	Total	Class A voting Common Stock [Member]	Capital in Excess of Par Value [Member]	Deferred Directors' Compensation [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Balances at Sep. 30, 2015	$ 127,004,675	$ 280,938	$ 2,993,119	$ 3,084,289	$ 125,446,473	$ (4,800,144)
Balances, shares at Sep. 30, 2015		16,863,004
Balances, Treasury shares at Sep. 30, 2015						(302,623)
Purchase of treasury stock	(117,165)					$ (117,165)
Purchase of treasury stock, shares						(7,477)
Restricted stock awards	644,783		644,783
Net income (loss)	(11,024,074)				(11,024,074)
Dividends ($.12 per share)	(2,007,658)				(2,007,658)
Distribution of restricted stock to officers and directors	(43,657)		(551,256)			$ 507,599
Distribution of restricted stock to officers and directors, shares						32,005
Distribution of deferred directors' compensation			(831)	(10,541)		$ 11,372
Distribution of deferred directors' compensation, shares						717
Increase in deferred directors' compensation charged to expense	247,835			247,835
Balances at Jun. 30, 2016	114,704,739	$ 280,938	3,085,815	3,321,583	112,414,741	$ (4,398,338)
Balances, shares at Jun. 30, 2016		16,863,004
Balances, Treasury shares at Jun. 30, 2016						(277,378)
Balances at Sep. 30, 2016	$ 115,191,819	$ 280,938	3,191,056	3,403,213	112,482,284	$ (4,165,672)
Balances, shares at Sep. 30, 2016		16,863,004
Balances, Treasury shares at Sep. 30, 2016	(262,708)					(262,708)
Purchase of treasury stock	$ (407,677)					$ (407,677)
Purchase of treasury stock, shares						(17,119)
Issuance of treasury shares to ESOP	(18)		(2)			$ (16)
Issuance of treasury shares to ESOP, shares						(1)
Restricted stock awards	454,854		454,854
Net income (loss)	2,492,799				2,492,799
Dividends ($.12 per share)	(2,012,329)				(2,012,329)
Distribution of restricted stock to officers and directors	622		(968,617)			$ 969,239
Distribution of restricted stock to officers and directors, shares						60,624
Distribution of deferred directors' compensation	(1)		(145,469)	(301,963)		$ 447,431
Distribution of deferred directors' compensation, shares						27,216
Increase in deferred directors' compensation charged to expense	266,182			266,182
Balances at Jun. 30, 2017	$ 115,986,251	$ 280,938	$ 2,531,822	$ 3,367,432	$ 112,962,754	$ (3,156,695)
Balances, shares at Jun. 30, 2017		16,863,004
Balances, Treasury shares at Jun. 30, 2017	(191,988)					(191,988)

Statements Of Stockholders' Eq6

Statements Of Stockholders' Equity (Parenthetical) - $ / shares	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.12	$ 0.12

Condensed Statements Of Cash Fl

Condensed Statements Of Cash Flows - USD ($)	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating Activities
Net income (loss)	$ 2,492,799	$ (11,024,074)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	13,654,268	18,963,017
Impairment	10,788	11,849,064
Provision for deferred income taxes	149,000	(10,344,000)
Gain from leasing fee mineral acreage	(3,999,632)	(7,187,377)
Proceeds from leasing fee mineral acreage	4,026,283	7,494,570
Net (gain) loss on sales of assets	87,161	(271,080)
Directors' deferred compensation expense	266,182	247,835
Restricted stock awards	454,854	644,783
Other	2,897	73,527
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	(564,767)	3,472,291
Fair value of derivative contracts	(1,879,668)	5,901,280
Refundable production taxes		476,001
Other current assets	196,362	69,237
Accounts payable	(127,375)	(698,593)
Income taxes receivable	(488,112)	345,897
Income taxes payable		659,319
Accrued liabilities	40,197	(118,403)
Total adjustments	11,828,438	31,577,368
Net cash provided by operating activities	14,321,237	20,553,294
Investing Activities
Capital expenditures, including dry hole costs	(18,011,721)	(3,359,518)
Investments in partnerships	(18,531)	50,126
Proceeds from sales of assets	718,700	627,547
Net cash provided (used) by investing activities	(17,311,552)	(2,681,845)
Financing Activities
Borrowings under debt agreement	16,702,602	8,560,234
Payments of loan principal	(11,202,602)	(24,360,234)
Purchases of treasury stock	(407,677)	(117,165)
Payments of dividends	(2,012,329)	(2,007,658)
Excess tax benefit on stock-based compensation		(44,000)
Net cash provided (used) by financing activities	3,079,994	(17,968,823)
Increase (decrease) in cash and cash equivalents	89,679	(97,374)
Cash and cash equivalents at beginning of period	471,213	603,915
Cash and cash equivalents at end of period	560,892	506,541
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	60,276	8,156
Gross additions to properties and equipment	19,579,304	3,529,104
Net (increase) decrease in accounts payable for properties and equipment additions	(1,567,583)	(169,586)
Capital expenditures and acquisitions, including dry hole costs	$ 18,011,721	$ 3,359,518

Basis of Presentation and Accou

Basis of Presentation and Accounting Principles	9 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Basis Of Presentation And Accounting Principles	NOTE 1: Basis of Presentation and Accounting Principles Basis of Presentation The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30. Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2016 Annual Report on Form 10-K. Adoption of New Accounting Pronouncements In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , such as senior notes, term loans and note payables, Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $172,613 and $263,584 as of June 30, 2017, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $310,900 as of September 30, 2016, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17. In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments The Company early adopted ASU 2016-15 as of December 31, 2016. As a result of the adoption, the Company reclassified , which totaled $4,026,283 and $7,494,570 for the nine months ended , res Adoption of ASU had no impact on the Company's current and previously reported shareholders' equity, results of operations or . The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on Form 10-Q have been adjusted to reflect the ret . In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively). The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the nine-month period ended June 30, 2017, versus “Capital in excess of par” on the Condensed Balance Sheets in the nine-month period ended June 30, 2016, as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows (Purchases of Treasury Stock). This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past. The adoption of this ASU could cause volatility in the effective tax rate going forward. New Accounting Pronouncements yet to be Adopted In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842) In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

Income Taxes

Income Taxes	9 Months Ended
	Jun. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	NOTE 2: Income Taxes The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. The adoption of ASU 2016-09 will also increase volatility in the effective tax rate going forward. Excess tax benefits and deficiencies of stock based compensation will be recognized as income tax expense (benefit) in the statement of operations prospectively versus additional paid in capital in the equity section of the balance sheet as was previously required. Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the nine months ended June 30, 2017, was a 10% provision as compared to a 42% benefit for the nine months ended June 30, 2016. The effective tax rate for the quarter ended June 30, 2017, was a 31% provision as compared to a 55% benefit for the quarter ended June 30, 2016.

Basic And Diluted Earnings (Los

Basic And Diluted Earnings (Loss) Per Share	9 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Basic And Diluted Earnings (Loss) Per Share	NOTE 3: Basic and Diluted Earnings (Loss) per Share Basic and diluted earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Long-Term Debt	NOTE 4: Long-term Debt The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2018. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $155,271,161 at June 30, 2017. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2017, the effective interest rate was 3.26%. The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates. Determinations of the borrowing base are made semi-annually (June and December) or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. In June 2017, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as defined by bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At June 30, 2017, the Company was in compliance with the covenants of the loan agreement and has $30,000,000 of availability under its outstanding credit facility.

Deferred Compensation Plan For

Deferred Compensation Plan For Non-Employee Directors	9 Months Ended
	Jun. 30, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Deferred Compensation Plan For Non-Employee Directors	NOTE 5: Deferred Compensation Plan for Non-Employee Directors Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors provides that each outside director may individually elect to be credited with future unissued shares of Company common stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director be issued under the Deferred Compensation Plan for Non-Employee Directors. Directors may elect to receive shares, when issued, over annual time periods up to ten years. The promise to issue such shares in the future is an unsecured obligation of the Company.

Restricted Stock Plan

Restricted Stock Plan	9 Months Ended
	Jun. 30, 2017
Restricted Stock Plan [Abstract]
Restricted Stock Plan	NOTE 6: Restricted Stock Plan In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders. Effective in May 2014, the board of directors adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. On December 9, 2016, the Company awarded 6,845 non-performance based shares and 20,531 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $176,260 and $292,884, respectively. The fair value for the performance and the non-performance based awards will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock prices as compared to the Dow Jones Select Oil Exploration and Production Index (DJSOEP) prices utilizing a Monte Carlo model covering the performance period (December 9, 2016, through December 9, 2019). On December 31, 2016, the Company awarded 8,916 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock vests quarterly over one year starting on March 31, 2017. The restricted stock contains non-forfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $209,970. The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock. Three Months Ended Nine Months Ended June 30, June 30, 2017 2016 2017 2016 Performance based, restricted stock $ 51,302 $ 40,380 $ 181,820 $ 350,270 Non-performance based, restricted stock 85,919 96,308 273,034 294,513 Total compensation expense $ 137,221 $ 136,688 $ 454,854 $ 644,783 A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. As of June 30, 2017 Unrecognized Compensation Cost Weighted Average Period (in years) Performance based, restricted stock $ 318,920 1.98 Non-performance based, restricted stock 317,247 1.51 Total $ 636,167 Upon vesting, shares are expected to be issued out of shares held in treasury.

Oil, NGL And Natural Gas Reserv

Oil, NGL And Natural Gas Reserves	9 Months Ended
	Jun. 30, 2017
Extractive Industries [Abstract]
Oil, NGL And Natural Gas Reserves	NOTE 7: Oil, NGL and Natural Gas Reserves Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for retirement of assets and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

Impairment

Impairment	9 Months Ended
	Jun. 30, 2017
Impairment [Abstract]
Impairment	NOTE 8: Impairment All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as: inflation rates; future drilling and completion costs; future sales prices for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three months ended June 30, 2017 and 2016, the assessment resulted in impairment provisions on producing properties of $0 and $0, respectively. For the nine months ended June 30, 2017 and 2016, the assessment resulted in impairment provisions on producing properties of $10,788 and $11,849,064, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

Capitalized Costs

Capitalized Costs	9 Months Ended
	Jun. 30, 2017
Extractive Industries [Abstract]
Capitalized Costs	NOTE 9: Capitalized Costs As of June 30, 2017, and September 30, 2016, non-producing oil and natural gas properties include costs of $0 and $5,917, respectively, on exploratory wells which were drilling and/or testing.

Derivatives

Derivatives	9 Months Ended
	Jun. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivatives	NOTE 10: Derivatives The Company has entered into commodity price derivative agreements including fixed swap contracts and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below. Derivative contracts in place as of June 30, 2017 Production volume Contract period covered per month Index Contract price Natural gas costless collars January - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.47 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling April - December 2017 30,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.65 ceiling May - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.60 ceiling May - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.20 floor / $3.65 ceiling January - March 2018 100,000 Mmbtu NYMEX Henry Hub $3.50 floor / $3.95 ceiling January - March 2018 150,000 Mmbtu NYMEX Henry Hub $3.40 floor / $3.95 ceiling January - December 2018 40,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling Natural gas fixed price swaps January - December 2017 25,000 Mmbtu NYMEX Henry Hub $3.100 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.070 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.210 April - December 2017 30,000 Mmbtu NYMEX Henry Hub $3.300 July - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.510 January - March 2018 50,000 Mmbtu NYMEX Henry Hub $3.700 January - March 2018 75,000 Mmbtu NYMEX Henry Hub $3.575 January - March 2018 100,000 Mmbtu NYMEX Henry Hub $3.520 Oil costless collars January - December 2017 3,000 Bbls NYMEX WTI $50.00 floor / $55.00 ceiling January - December 2017 3,000 Bbls NYMEX WTI $52.00 floor / $58.00 ceiling January - December 2017 3,000 Bbls NYMEX WTI $53.00 floor / $57.75 ceiling April - December 2017 2,000 Bbls NYMEX WTI $50.00 floor / $57.50 ceiling July - December 2017 5,000 Bbls NYMEX WTI $45.00 floor / $56.25 ceiling Oil fixed price swaps January - December 2017 3,000 Bbls NYMEX WTI $53.89 April - December 2017 2,000 Bbls NYMEX WTI $54.20 January - March 2018 4,000 Bbls NYMEX WTI $54.00 Derivative contracts in place as of September 30, 2016 Production volume Contract period covered per month Index Contract price Natural gas costless collars April - October 2016 200,000 Mmbtu NYMEX Henry Hub $1.95 floor / $2.40 ceiling October - December 2016 70,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.05 ceiling October - December 2016 50,000 Mmbtu NYMEX Henry Hub $2.90 floor / $3.40 ceiling November 2016 - March 2017 50,000 Mmbtu NYMEX Henry Hub $2.25 floor / $3.65 ceiling November 2016 - March 2017 80,000 Mmbtu NYMEX Henry Hub $2.25 floor / $3.95 ceiling November 2016 - March 2017 50,000 Mmbtu NYMEX Henry Hub $2.60 floor / $3.25 ceiling January - June 2017 50,000 Mmbtu NYMEX Henry Hub $2.85 floor / $3.35 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.47 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling Natural gas fixed price swaps October 2016 100,000 Mmbtu NYMEX Henry Hub $2.410 October 2016 - March 2017 25,000 Mmbtu NYMEX Henry Hub $3.200 November 2016 - April 2017 80,000 Mmbtu NYMEX Henry Hub $2.955 January - December 2017 25,000 Mmbtu NYMEX Henry Hub $3.100 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.070 Oil costless collars July - December 2016 3,000 Bbls NYMEX WTI $35.00 floor / $49.00 ceiling October - December 2016 3,000 Bbls NYMEX WTI $40.00 floor / $47.25 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $40.00 floor / $58.50 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $45.00 floor / $54.00 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $45.00 floor / $55.50 ceiling The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net asset of $1,451,397 as of June 30, 2017, and a net liability of $428,271 as of September 30, 2016. The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at June 30, 2017, and September 30, 2016. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2017, and September 30, 2016. June 30, 2017 September 30, 2016 Fair Value (a) Fair Value (a) Commodity Contracts Commodity Contracts Current Assets Current Liabilities Non-Current Assets Current Assets Current Liabilities Non-Current Assets Non-Current Liabilities Gross amounts recognized $ 1,492,208 $ 52,522 $ 11,711 $ 68,235 $ 471,847 $ 4,759 $ 29,418 Offsetting adjustments (52,522 ) (52,522 ) - (68,235 ) (68,235 ) (4,759 ) (4,759 ) Net presentation on Condensed Balance Sheets $ 1,439,686 $ - $ 11,711 $ - $ 403,612 $ - $ 24,659 (a) See Fair Value Measurements section for further disclosures regarding fair value of financial instruments. The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	NOTE 11: Fair Value Measurements Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2017. Fair Value Measurement at June 30, 2017 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 732,223 $ - $ 732,223 Derivative Contracts - Collars $ - $ - $ 719,174 $ 719,174 Level 2 – Market Approach - The fair values of the Company’s swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness. Level 3 – The fair values of the Company’s costless collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness. The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives. The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements. Instrument Type Unobservable Input Range Weighted Average Fair Value June 30, 2017 Oil Collars Oil price volatility curve 0% - 21.50% 13.73% $ 459,049 Natural Gas Collars Gas price volatility curve 0% - 34.96% 19.80% $ 260,125 A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Condensed Statements of Operations. Derivatives Balance of Level 3 as of October 1, 2016 $ (316,658 ) Total gains or (losses) Included in earnings 1,222,713 Included in other comprehensive income (loss) - Purchases, issuances and settlements (186,881 ) Transfers in and out of Level 3 - Balance of Level 3 as of June 30, 2017 $ 719,174 The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Quarter Ended June 30, 2017 2016 Fair Value Impairment Fair Value Impairment Producing Properties (a) $ - $ - $ - $ - Nine Months Ended June 30, 2017 2016 Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 7,868 $ 10,788 $ 9,741,650 $ 11,849,064 (a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. At June 30, 2017, and September 30, 2016, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Basis of Presentation and Acc19

Basis of Presentation and Accounting Principles (Policies)	9 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Basis Of Presentation	Basis of Presentation The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30. Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2016 Annual Report on Form 10-K.
Adoption Of New Accounting Pronouncements	Adoption of New Accounting Pronouncements In April 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs , such as senior notes, term loans and note payables, Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset In August 2015, the FASB issued ASU 2015-15, Interest—Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements The Company adopted ASU 2015-03 and ASU 2015-15 as of December 31, 2016. The Company elected to continue to show debt issuance costs associated with its credit facility (Company’s only debt) as assets versus a direct reduction of the debt liability. Therefore, the adoption had no impact on the Company's current and previously reported balance sheets, shareholders' equity, results of operations, or cash flows. In accordance with ASU 2015-15, unamortized debt issuance costs associated with the Company's credit facility, which amounted to $172,613 and $263,584 as of June 30, 2017, and September 30, 2016, respectively, remain reflected in "Other property and equipment" on the balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $310,900 as of September 30, 2016, from "Deferred income taxes" in current assets to “Deferred income tax, net” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-Q have been adjusted to reflect the retroactive adoption of ASU 2015-17. In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments The Company early adopted ASU 2016-15 as of December 31, 2016. As a result of the adoption, the Company reclassified , which totaled $4,026,283 and $7,494,570 for the nine months ended , res Adoption of ASU had no impact on the Company's current and previously reported shareholders' equity, results of operations or . The affected prior period balances in the Condensed Statements of Cash Flows presented throughout this report on Form 10-Q have been adjusted to reflect the ret . In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting changes how companies account for certain aspects of share-based payment awards, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The standard is effective for interim and annual reporting periods beginning after December 15, 2016, and will be adopted either prospectively, retrospectively or using a modified retrospective transition approach depending on the topic covered in the standard. On a prospective basis companies will no longer record excess tax benefits and deficiencies in additional paid-in capital. Instead, excess tax benefits and deficiencies will be recognized as income tax expense or benefit in the income statement. This is expected to result in increased volatility in income tax expense/benefit and corresponding variations in the relationship between income tax expense/benefit and pre-tax income/loss from period to period. Also, companies will have to present excess tax benefits and deficiencies as operating activities on the statement of cash flows (prospectively or retrospectively). The Company early adopted ASU 2016-09 as of October 1, 2016. As a result of the adoption, the Company recorded $228,000 of excess tax benefits from stock-based compensation in the “Provision (benefit) for income taxes” on the Condensed Statements of Operations in the nine-month period ended June 30, 2017, versus “Capital in excess of par” on the Condensed Balance Sheets in the nine-month period ended June 30, 2016, as was previously required. This part of the guidance is to be applied prospectively, so the prior period balances have not been reclassified. The Company also presented excess tax benefits from stock-based compensation in the “Operating Activities” section of the Condensed Statements of Cash Flows in the current period versus the “Financing Activities” section of the Condensed Statements of Cash Flows as was previously presented. The Company has elected to apply this part of the guidance prospectively, so the prior period balances have not been reclassified. The guidance also requires that companies present employees taxes paid upon vesting as financing activities on the statement of cash flows (Purchases of Treasury Stock). This requirement had no impact on the Company, as this has been the practice historically. The Company is also electing to account for forfeitures of awards as they occur, instead of estimating a forfeiture amount. A cumulative-effect adjustment to retained earnings was not necessary for this transition as there were no material forfeitures estimated or incurred in the past. The adoption of this ASU could cause volatility in the effective tax rate going forward.
New Accounting Pronouncements Yet To Be Adopted	New Accounting Pronouncements yet to be Adopted In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842) In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

Restricted Stock Plan (Tables)

Restricted Stock Plan (Tables)	9 Months Ended
	Jun. 30, 2017
Restricted Stock Plan [Abstract]
Summary Of Pre-Tax Compensation Expense	The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2017 and 2016, related to the Company’s performance based and non-performance based restricted stock. Three Months Ended Nine Months Ended June 30, June 30, 2017 2016 2017 2016 Performance based, restricted stock $ 51,302 $ 40,380 $ 181,820 $ 350,270 Non-performance based, restricted stock 85,919 96,308 273,034 294,513 Total compensation expense $ 137,221 $ 136,688 $ 454,854 $ 644,783
Summary Of Unrecognized Compensation Cost	A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table. As of June 30, 2017 Unrecognized Compensation Cost Weighted Average Period (in years) Performance based, restricted stock $ 318,920 1.98 Non-performance based, restricted stock 317,247 1.51 Total $ 636,167

Derivatives (Tables)

Derivatives (Tables)	9 Months Ended
	Jun. 30, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary Of Derivative Instruments Contracts	Derivative contracts in place as of June 30, 2017 Production volume Contract period covered per month Index Contract price Natural gas costless collars January - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.47 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling April - December 2017 30,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.65 ceiling May - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.60 ceiling May - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.20 floor / $3.65 ceiling January - March 2018 100,000 Mmbtu NYMEX Henry Hub $3.50 floor / $3.95 ceiling January - March 2018 150,000 Mmbtu NYMEX Henry Hub $3.40 floor / $3.95 ceiling January - December 2018 40,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling Natural gas fixed price swaps January - December 2017 25,000 Mmbtu NYMEX Henry Hub $3.100 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.070 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.210 April - December 2017 30,000 Mmbtu NYMEX Henry Hub $3.300 July - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.510 January - March 2018 50,000 Mmbtu NYMEX Henry Hub $3.700 January - March 2018 75,000 Mmbtu NYMEX Henry Hub $3.575 January - March 2018 100,000 Mmbtu NYMEX Henry Hub $3.520 Oil costless collars January - December 2017 3,000 Bbls NYMEX WTI $50.00 floor / $55.00 ceiling January - December 2017 3,000 Bbls NYMEX WTI $52.00 floor / $58.00 ceiling January - December 2017 3,000 Bbls NYMEX WTI $53.00 floor / $57.75 ceiling April - December 2017 2,000 Bbls NYMEX WTI $50.00 floor / $57.50 ceiling July - December 2017 5,000 Bbls NYMEX WTI $45.00 floor / $56.25 ceiling Oil fixed price swaps January - December 2017 3,000 Bbls NYMEX WTI $53.89 April - December 2017 2,000 Bbls NYMEX WTI $54.20 January - March 2018 4,000 Bbls NYMEX WTI $54.00 Derivative contracts in place as of September 30, 2016 Production volume Contract period covered per month Index Contract price Natural gas costless collars April - October 2016 200,000 Mmbtu NYMEX Henry Hub $1.95 floor / $2.40 ceiling October - December 2016 70,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.05 ceiling October - December 2016 50,000 Mmbtu NYMEX Henry Hub $2.90 floor / $3.40 ceiling November 2016 - March 2017 50,000 Mmbtu NYMEX Henry Hub $2.25 floor / $3.65 ceiling November 2016 - March 2017 80,000 Mmbtu NYMEX Henry Hub $2.25 floor / $3.95 ceiling November 2016 - March 2017 50,000 Mmbtu NYMEX Henry Hub $2.60 floor / $3.25 ceiling January - June 2017 50,000 Mmbtu NYMEX Henry Hub $2.85 floor / $3.35 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.47 ceiling January - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.00 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.80 floor / $3.35 ceiling April - December 2017 50,000 Mmbtu NYMEX Henry Hub $2.75 floor / $3.35 ceiling Natural gas fixed price swaps October 2016 100,000 Mmbtu NYMEX Henry Hub $2.410 October 2016 - March 2017 25,000 Mmbtu NYMEX Henry Hub $3.200 November 2016 - April 2017 80,000 Mmbtu NYMEX Henry Hub $2.955 January - December 2017 25,000 Mmbtu NYMEX Henry Hub $3.100 April - December 2017 50,000 Mmbtu NYMEX Henry Hub $3.070 Oil costless collars July - December 2016 3,000 Bbls NYMEX WTI $35.00 floor / $49.00 ceiling October - December 2016 3,000 Bbls NYMEX WTI $40.00 floor / $47.25 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $40.00 floor / $58.50 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $45.00 floor / $54.00 ceiling October 2016 - March 2017 3,000 Bbls NYMEX WTI $45.00 floor / $55.50 ceiling
Summary Of Derivative Contracts	June 30, 2017 September 30, 2016 Fair Value (a) Fair Value (a) Commodity Contracts Commodity Contracts Current Assets Current Liabilities Non-Current Assets Current Assets Current Liabilities Non-Current Assets Non-Current Liabilities Gross amounts recognized $ 1,492,208 $ 52,522 $ 11,711 $ 68,235 $ 471,847 $ 4,759 $ 29,418 Offsetting adjustments (52,522 ) (52,522 ) - (68,235 ) (68,235 ) (4,759 ) (4,759 ) Net presentation on Condensed Balance Sheets $ 1,439,686 $ - $ 11,711 $ - $ 403,612 $ - $ 24,659 (a) See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis	Fair Value Measurement at June 30, 2017 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total Fair (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 732,223 $ - $ 732,223 Derivative Contracts - Collars $ - $ - $ 719,174 $ 719,174
Summary Of Unobservable Inputs For Level 3 Fair Value Measurements	Instrument Type Unobservable Input Range Weighted Average Fair Value June 30, 2017 Oil Collars Oil price volatility curve 0% - 21.50% 13.73% $ 459,049 Natural Gas Collars Gas price volatility curve 0% - 34.96% 19.80% $ 260,125
Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements	Derivatives Balance of Level 3 as of October 1, 2016 $ (316,658 ) Total gains or (losses) Included in earnings 1,222,713 Included in other comprehensive income (loss) - Purchases, issuances and settlements (186,881 ) Transfers in and out of Level 3 - Balance of Level 3 as of June 30, 2017 $ 719,174
Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3	Quarter Ended June 30, 2017 2016 Fair Value Impairment Fair Value Impairment Producing Properties (a) $ - $ - $ - $ - Nine Months Ended June 30, 2017 2016 Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 7,868 $ 10,788 $ 9,741,650 $ 11,849,064 (a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

Basis of Presentation and Acc23

Basis of Presentation and Accounting Principles (Narrative) (Details) - USD ($)	Sep. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Basis Of Presentation And Accounting Principles [Line Items]
Provision (benefit) for income taxes		$ 567,000	$ (944,000)	$ 263,000	$ (7,887,000)
ASU 2015-15 [Member] | Other Property and Equipment [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Unamortized debt issuance expense	$ 263,584	$ 172,613		172,613
ASU 2015-17 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Prior period reclassification	$ 310,900
ASU 2016-15 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Prior period reclassification				4,026,283	$ 7,494,570
ASU 2016-09 [Member]
Basis Of Presentation And Accounting Principles [Line Items]
Provision (benefit) for income taxes				$ 228,000

Income Taxes (Details)

Income Taxes (Details)	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Effective tax rate	31.00%	(55.00%)	10.00%	(42.00%)

Long-Term Debt (Details)

Long-Term Debt (Details) - Revolving Credit Facility [Member]	9 Months Ended
	Jun. 30, 2017USD ($)
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Borrowing base of credit facility	$ 80,000,000
Credit facility maturity	Nov. 30, 2018
Properties net book value	$ 155,271,161
Effective Interest rate	3.26%
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 30,000,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	100.00%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.375%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.875%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.125%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.625%

Deferred Compensation Plan Fo26

Deferred Compensation Plan For Non-Employee Directors (Details)	9 Months Ended
	Jun. 30, 2017
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years

Restricted Stock Plan (Narrativ

Restricted Stock Plan (Narrative) (Details) - USD ($)	Dec. 09, 2016	Dec. 31, 2016	Jun. 30, 2017	Mar. 31, 2014	Mar. 31, 2010
Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period			3 years
Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock vesting period			1 year
Non Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	6,845
Fair value of shares awarded	$ 176,260
Non Performance Based Restricted Stock [Member] | Non Employee Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded		8,916
Fair value of shares awarded		$ 209,970
Performance Based Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares awarded	20,531
Fair value of shares awarded	$ 292,884
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized				500,000	200,000

Restricted Stock Plan (Summary

Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 137,221	$ 136,688	$ 454,854	$ 644,783
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	51,302	40,380	181,820	350,270
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 85,919	$ 96,308	$ 273,034	$ 294,513

Restricted Stock Plan (Summar29

Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	9 Months Ended
	Jun. 30, 2017USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 636,167
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 318,920
Weighted Average Period (in years)	1 year 11 months 23 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 317,247
Weighted Average Period (in years)	1 year 6 months 3 days

Oil, NGL And Natural Gas Rese30

Oil, NGL And Natural Gas Reserves (Details)	9 Months Ended
	Jun. 30, 2017
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Computation of Oil, Natural Gas and NGL Reserves	12 months

Impairment (Details)

Impairment (Details) - USD ($)	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Impairment [Abstract]
Impairment	$ 0	$ 0	$ 10,788	$ 11,849,064

Capitalized Costs (Details)

Capitalized Costs (Details) - USD ($)	Jun. 30, 2017	Sep. 30, 2016
Extractive Industries [Abstract]
Cost of Non-Producing Oil and Natural Gas Properties	$ 0	$ 5,917

Derivatives (Summary Of Derivat

Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Jun. 30, 2017MMBTU$ / MMBTU$ / bblbbl	Sep. 30, 2016MMBTU$ / MMBTU$ / bblbbl
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	200,000
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.80	1.95
Natural Gas Costless Collars [Member] | Derivative Contract Period One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.47	2.40
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	70,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3	2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.05
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.80	2.90
Natural Gas Costless Collars [Member] | Derivative Contract Period Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.40
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.75	2.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Four [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.65
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	30,000	80,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3	2.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Five [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.65	3.95
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3	2.60
Natural Gas Costless Collars [Member] | Derivative Contract Period Six [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.60	3.25
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.20	2.85
Natural Gas Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.65	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.50	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.95	3.47
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	150,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	3.40	3
Natural Gas Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.95	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	40,000	50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	2.75	2.80
Natural Gas Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	3.35	3.35
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU		50,000
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price		2.75
Natural Gas Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price		3.35
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	25,000
Contract price	3.100
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	100,000
Contract price	3.070	2.410
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	25,000
Contract price	3.210	3.200
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	30,000	80,000
Contract price	3.300	2.955
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	25,000
Contract price	3.510	3.100
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	50,000	50,000
Contract price	3.700	3.070
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	75,000
Contract price	3.575
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price	3.520
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		35
Oil Costless Collars [Member] | Derivative Contract Period Seventeen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		49
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl		3,000
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl		40
Oil Costless Collars [Member] | Derivative Contract Period Eighteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl		47.25
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000	3,000
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	50	40
Oil Costless Collars [Member] | Derivative Contract Period Nineteen [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	55	58.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	52	45
Oil Costless Collars [Member] | Derivative Contract Period Twenty [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	58	54
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000	3,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	53	45
Oil Costless Collars [Member] | Derivative Contract Period Twenty One [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	57.75	55.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Two [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	57.50
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	5,000
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Minimum [Member]
Derivative [Line Items]
Contract price | $ / bbl	45
Oil Costless Collars [Member] | Derivative Contract Period Twenty Three [Member] | Maximum [Member]
Derivative [Line Items]
Contract price | $ / bbl	56.25
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Four [Member]
Derivative [Line Items]
Contract price | $ / bbl	53.89
Production volume covered per month - Oil | bbl	3,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Five [Member]
Derivative [Line Items]
Contract price | $ / bbl	54.20
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty Six [Member]
Derivative [Line Items]
Contract price | $ / bbl	54
Production volume covered per month - Oil | bbl	4,000

Derivatives (Narrative) (Detail

Derivatives (Narrative) (Details) - USD ($)	Jun. 30, 2017	Sep. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value of derivative contracts, asset	$ 1,451,397
Fair value of derivative contracts, liability		$ 428,271

Derivatives (Summary Of Deriv35

Derivatives (Summary Of Derivative Contracts) (Details) - USD ($)		Jun. 30, 2017	Sep. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	[1]	$ 1,492,208	$ 68,235
Offsetting adjustments - Current Assets	[1]	(52,522)	(68,235)
Net presentation on Condensed Balance Sheets - Current Assets	[1]	1,439,686
Gross amounts recognized - Current Liabilities	[1]	52,522	471,847
Offsetting adjustments - Current Liabilities	[1]	(52,522)	(68,235)
Net presentation on Condensed Balance Sheets - Current Liabilities	[1]		403,612
Gross amounts recognized - Non-Current Assets	[1]	11,711	4,759
Offsetting adjustments - Non-Current Assets	[1]		(4,759)
Net presentation on Condensed Balance Sheets - Non-Current Assets	[1]	$ 11,711
Gross amounts recognized - Non-Current Liabilities	[1]		29,418
Offsetting adjustments - Non-Current Liabilities	[1]		(4,759)
Net presentation on Condensed Balance Sheets - Non-Current Liabilities	[1]		$ 24,659
[1]	See Fair Value Measurements section for further disclosures regarding fair value of financial instruments

Fair Value Measurements (Summar

Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details)	Jun. 30, 2017USD ($)
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 732,223
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	732,223
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	719,174
Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 719,174

Fair Value Measurements (Summ37

Fair Value Measurements (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details)	9 Months Ended
	Jun. 30, 2017USD ($)
Oil Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Oil price volatility curve
Weighted Average	13.73%
Fair Value Assets (Liabilities)	$ 459,049
Oil Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Oil Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	21.50%
Natural Gas Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Gas price volatility curve
Weighted Average	19.80%
Fair Value Assets (Liabilities)	$ 260,125
Natural Gas Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Natural Gas Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	34.96%

Fair Value Measurements (Summ38

Fair Value Measurements (Summary Of Reconciliation Of Derivative Contracts Classified As Level 3 Measurements) (Details)	9 Months Ended
	Jun. 30, 2017USD ($)
Fair Value Disclosures [Abstract]
Balance of Level 3 as of October 1, 2016	$ (316,658)
Total gains or (losses) included in earnings	1,222,713
Purchases, issuances and settlements	(186,881)
Balance of Level 3 as of June 30, 2017	$ 719,174

Fair Value Measurements (Summ39

Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($)		3 Months Ended		9 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Producing Properties, Fair Value	[1]			$ 7,868	$ 9,741,650
Producing Properties, Impairment		$ 0	$ 0	$ 10,788	$ 11,849,064
[1]	At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.